Adsorption of Polar Oil Components onto Chalk: Impact of Silica content on Initial Wetting

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FACULTY OF SCIENCE AND TECHNOLOGY

MASTER’S THESIS

Study programme/specialisation:

Master in Petroleum Technology/

Reservoir Engineering

Spring semester, 2018

Open Author:

Isaac Klewiah ………

(signature of author) Supervisors:

Prof. Skule Strand

Ass. Prof. Tina Puntervold Co-Supervisor:

Dr. Ivàn Piñerez Torrijros Title of master’s thesis:

Adsorption of Polar Oil Components onto Chalk: Impact of Silica content on Initial Wetting

Credits (ECTS) : 30 Keywords:

• Enhanced Oil Recovery

• Imbibition

• Smart Water flooding

• Adsorption

• Polar Oil Components

• Chalk

Number of pages: 91

+ supplemental material/other: 5

Stavanger, 30^th July, 2018

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Dedication

I dedicate this work to my dear parents; Mr. Paul Klewiah and Mrs. Gladys Klewiah. They both received little formal education but have persevered relentlessly to educate all six (6) children, even including myself, their last child. To them, I say Ayekoo!!

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Acknowledgement

I express my profound gratitude to God for providing me with strength and wisdom to complete this research project. I would also like to thank Professor Skule Strand and Associate Professor Tina Puntervold for their guidance, support, motivation and advice as my supervisors in this thesis. Special thanks to Dr. Ivàn Piñerez Torrijros for his enormous assistance during the laboratory work and support at the time when I got cycle-injured midway into this project. To my family and friends who believed in my capabilities and inspired me to reach for greatness, I am truly grateful. The selfless support offered by Mr. and Mrs. Nartey and Eld. Samuel Erzuah during my study period is well appreciated as well. Further appreciation is extended to Miltos, Kristoffer, Simen and Anna, my colleagues in the lab, for making the sessions fun and for the mutual support offered.

Finally, I thank the Norwegian government and the University of Stavanger for the top-notch training given.

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Abstract

The wetting state of reservoir rocks, particularly naturally fractured chalk, is fundamental in the efficient application of advanced oil recovery methods by injection of water. In the subsurface crude oil/brine/rock system, a chemical equilibrium between the phases has established a characteristic initial wetting of the system. Experimental studies have revealed the adsorption of polar organic components from crude oil onto the rock surface as the main influence on initial wetting. In the Laboratory, outcrop chalks, are often used as analog materials for chalk reservoir studies. Stevns Klint (SK) chalk, which is a relatively pure outcrop, has been vigorously studied regarding initial wetting but little attention has been given to the adsorption efficiency of polar components onto outcrop chalk of considerable silica impurity.

In this study, experiments have been performed on Aalborg (AA) chalk material, with significant amount of silica (SiO2) impurity (6-8 At% Si) and possible silicate materials present as clay flakes to quantify the retention of polar acidic and basic components of crude oil onto the chalk surface. In previous experiments, the adsorption has been examined on SK chalk samples (with < 2 At% Si) under the same experimental conditions so the results from this study are analyzed in comparison to the previous knowledge.

Approximately 7PV of Crude oil with known acid number (AN) and base number (BN) was flooded through a core sample (AA#1) at 50°C to measure the changes in AN and BN at the core outlet. The amount of crude oil polar organic components adsorbed was quantified in relation to the area above the curve plot of effluent AN/BN versus PV flooded. Another core (AA#2) was flooded with 5PV of the same crude oil to investigate the impact that crude oil injected volume has on Aalborg chalk wetting. Both oil-saturated samples were aged for 2 weeks at 50°C in the same crude oil and their wetting states evaluated by spontaneous imbibition (SI), forced imbibition (FI) and chromatographic wettability tests (CWT). The studies confirmed that; 1) The adsorption of polar crude oil components is an instantaneous process that occurs as soon as the oil contacts the porous media. 2) Adsorption of acidic components onto Aalborg chalk surface was less profound as compared to SK chalk. 3) The adsorption of basic components was significantly higher compared to SK chalk. 4) Water wetness increased with decreasing the number of pore volumes of crude oil injected.

The high silica content of Aalborg seems to inhibit adsorption of negatively charged acidic components but promotes higher adsorption of basic components and reveals the impact that chalk silica content will have on the initial wetting potential of the different polar components in crude oil. This is a fundamentally essential information for the developments of theoretical and chemical models to explain wettability alteration in chalk reservoirs and highlights the essence of exercising cautions discretion when choosing any outcrop chalk material for parametric laboratory studies to characterize natural reservoir chalk rock behavior.

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List of Tables

Table 1: Geological description of some outcrop chalks (Milter et al., 1996; Puntervold,

2008) ... 17

Table 2: Approximate relationship between contact angle and wettability ... 21

Table 3: core sample data. ... 39

Table 4: Oil properties ... 40

Table 5: Formation and Chromatographic brine composition and properties ... 41

Table 6: EDS analysis on Aalborg, plus SK for comparison ... 50

Table 7: core sample / adsorption data. ... 53

Table 8: Summary of results from wettability tests for the Aalborg core samples ... 61

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List of Figures

Figure 2.1: Illustration of the production stages in a reservoir’s production life. Smart water is

categorized and the essence for implementing EOR methods from day one is emphasized ... 7

Figure 2.2: Percent of total oil reserves and recovery factor in carbonates (Suhal, 2016) ... 8

Figure 2.3: EOR field projects in carbonates (Suhal, 2016) ... 8

Figure 3.1: Carbonate material growing in clear water (a), and images of carbonate-source eukaryotes with high degree microscopes. ... 14

Figure 3.2: SEM image of chalk showing the coccolithic rings and pore spaces. ... 15

Figure 4.1: Illustration of homogeneous wettability (Willhite et al., 1998) ... 19

Figure 4.2: Wettability of the COBR system (Andersen , 1986) ... 21

Figure 4.3: Relationship of wettability measurement by Amott and USBM testes to Pc curves for a mixed wettability system (Morrow, 1990) ... 23

Figure 4.4: Chromatographic separation of SCN– and SO42- for a preferentially water-wet system using heptane as oil phase (Strand, Standnes, & Austad, New wettability test for chalk based on chromatographic separation of thiocyante and sulphate, 2006b) ... 24

Figure 4.5: Illustration of oil adherence onto carbonate mineral surface in relation to the surface forces and interfacial interactions of Oil/Brine and Rock/Brine interfaces ... 26

Figure 4.6: Illustration of initial wetting of carbonate chalk rock in alkaline conditions. pH of the system influences the dissociation of polar organic components and dictates their ability to adhere onto charged surfaces. ... 28

Figure 4.7: The influence of AN, on oil recovery from chalk by spontaneous imbibition (Standnes et al., 2000). Increasing AN gives less water-wetness ... 29

Figure 4.8: Influence of BN on chalk wetting. Investigation at constant AN=0.5 shows increased water wetness with increasing BN (Puntervold, 2008) ... 30

Figure 4.9: Schematic representation of the displacement process in fractured medium ... 34

Figure 5.1: Illustration of the potential of ordinary seawater as an EOR fluid (Shariatpanahi et al., 2010) ... 35

Figure 5.2: Oil recovery from carbonate material demonstrating the benefit of optimizing seawater ionic compositions (Fathi et al., 2011) ... 36

Figure 5.3: Mechanistic illustration of smart water migration through a porous medium ... 36

Figure 5.4: Proposed mechanism for the wettability alteration induced by seawater at ordinary temperature (left) and at high temperature (right) (Zhang, et al., 2007) ... 37

Figure 5.5: Illustration of the symbiotic interaction between the PDIs in relation to the wetting alteration potential of brine (Zhang, et al., 2007). Spiking the brine with SO42- in the absence of Mg²⁺and Ca²⁺ ions has no effect on ultimate recovery. ... 38

Figure 6.1: Vacuum setup for brine saturation of cores, by Frida Layti (BSc 2015) ... 42

Figure 6.2: Hassler Core Holder used for all core flooding experiments ... 43

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Figure 6.3: Core cleaning experimental set-up ... 43 Figure 6.4: Oil saturation and fluid flooding setup Ingrid (BSc 2015) ... 44 Figure 6.5: Schematic of spontaneous imbibition in steel cells at high temperature Kristoffer (BSc 2018) ... 45 Figure 6.6: Schematic for spontaneous imbibition conducted at room temperature ... 45 Figure 7.1: SEM secondary electron image of unflooded Aalborg chalk core at magnification capacity of 100 (a); 5K (b) and 10K (c&d). ... 47 Figure 7.2: Capture of a possible clay flake protruding underneath a coccolith in the Aalborg core at a magnification capacity of 10, 000 ... 48 Figure 7.3: SEM of Aalborg (a &c) compared to Stevns Klint (b & d) at a magnification capacity of 5K (c&d) and 10K (a&d) ... 49 Figure 7.4: Adsorption of carboxylic material onto AA#1 chalk surface; Swi / T =0.1/50°C.

Core was flooded with crude oil of AN=0.35 mgKOH/g at a flow rate of 0.1ml/min. Total adsorbed species is 0.83 ... 51 Figure 7.5: Adsorption of basic material onto AA#1 chalk surface; Swi / T =0.1/50°C. Core was flooded with crude oil of BN=0.35 mgKOH/g at a flow rate of 0.1ml/min. Total adsorbed species is 1.02 ... 52 Figure 7.6: BN/AN adsorptioncomparison for AA#1 (ANads =0.83 & BNads =1.02) and SK-10 (ANads =1.33 & BNads =0.93) outcrop chalks ... 53 Figure 7.7: Dissociation of polar organic species in crude oil and ... 55 Figure 7.8: SI experiment on completely water-wet Aalborg Chalk, AA#3 (reference). Core was spontaneously imbibed at room temperature with DI water ... 56 Figure 7.9: Chromatographic wettability test for Aalborg reference core (AA#3) at room temperature. ... 57 Figure 7.10: Spontaneous and Forced Imbibition tests conducted on AA#1with an ultimate recovery of 47.6% OOIP and Iw*= 0.39 ... 57 Figure 7.11: Chromatographic wettability test on Aalborg core AA#1 saturated with ~7PV Oil ... 58 Figure 7.12: Recovery by spontaneous imbibition tests on 3 Aalborg cores at different

wetting conditions. Oil recovery decreases as the water-wetness decreases. ... 59 Figure 7.13: Recovey by Spontaneous Imbibition and Forced Imbibiton of FW in AA#1 (Iw*= 0.39) and AA#2 (Iw*= 0.45) ... 60 Figure 7.14: Chromatographic wettability test on Aalborg core AA#2 saturated with 5PV Oil ... 61

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Nomenclature

σ Interfacial Tension

θ Contact Angle

AA Aalborg Chalk AN Acid Number BN Base Number

COBR Crude Oil/Brine/Rock

CWT Chromatographic Wettability Method EOR Enhanced Oil Recovery

FI Forced Imbibition ICW Wetting Index (CWT)

Iw* Wetting index (Amott method) OOIP Original Oil In Place

Pc Capillary pressure PV Pore Volumes RF Recovery Factor

SI Spontaneous Imbibition SK Stevns Klint Chalk SW Seawater

Swi Initial water saturation

VBOS Vallhal Formation Water without Sulphate

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1 Introduction

1.1 Background

Carbonate reservoirs are known to contain a considerable portion of the global oil reserve and reported also, to have extensive natural fractures (Brownscombe et al., 1952; Mazzullo et al., 1992) and yield low ultimate recovery by conventional waterflooding techniques (Craig, 1971; Al-Lawati et al., 1996; Fidra, 1998) due to their unfavorable mixed- to oil-wet tendencies (Treiber et al., 1972;

Chilingar et al., 1983; Salathiel, 1973; Morrow, 1990). Thus, though these fractured reservoirs account for most of the oil produced worldwide, much of the original oil remains trapped in the subsurface and makes them a huge target for Enhanced Oil Recovery (EOR). Brownscombe et al., (1952) revealed spontaneous imbibition (SI) of injected fluids as the chief mechanism to yield high recovery efficiency in carbonate reservoirs. This assertion was confirmed and investigated by several authors (Wade, 1974; Cuiec et al., 1994; Akin et al., 1998; etcetera) and continues to receive attention from the scientific community. Water, however, will only imbibe spontaneously into the rock matrix and expel oil if the initial wettability of the carbonate rock matrixes is altered toward more water-wetness (Hirasaki et al., 2004). Many studies (Donaldson et al., 1969; Morrow 1990;

Jadhunandan et al., 1991; Cuiec et al., 1994; Austad et al., 1997; Fidra 1998; Zhou et al., 2000;

Morrow et al., 2001; Strand et al., 2006; Bourbiaux, 2009) have been conducted to investigate the effects of carbonate wetting conditions during waterflooding process.

The initial wettability of rocks is a result of the chemical equilibrium between the formation brine, oil and mineral surface (Cuiec, 1984; Cuiec, 1991), established over the geological period that spans the reservoir creation. Initial wetting is important as it governs in-situ fluid distribution, capillary pressure and relative fluid permeabilities; imposing an indirect effect on well rates and limits of economic hydrocarbon production. The brine chemistry has been shown (Israelachvili, 1985; Buckley et al., 1989; Hirasaki, 1991) to influence the wettability by parameters such as ionic composition, ionic concentration and the pH of the solution. It is widely accepted that brine is the first fluid (Buckley, 1996) to occupy the pore space, making the reservoir minerals originally water wet, until oil encroaches the rock-brine system. The idea of wetting alteration by crude oil was indirectly postulated by Burkhardt et al., (1958) and emphasized by Denekes et al., (1959) who investigated the native surface-active materials of crude oil that adsorb on rock mineral surfaces by looking at their chemical type, molecular weight and polarity of crude oil fractions. He concluded that the high molecular weight components had the greatest potential to alter wetting and that the presence of nitrogren- sulfur- or oxygen-containing functional groups [called Asphaltenes, as coined by Boussingault in 1837 (Chrisholm, 1911)] induced polarity of the fractions and enabled the crude to approach the charged mineral surfaces.

In the years that followed, several researchers (Craig, 1971; Cuiec, 1985; Hjelmeland et al., 1986;

Morrow et al., 1986; Gonzalez et al., 1986; Gloton et al., 1992; Akhlag et al., 1994; Buckley, 1996) further investigated this assertion and confirmed that crude oils contained components with polar functionality that can exhibit surface-active propensities and may readily attach onto the mineral

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surfaces to alter the primary wettability when migrating crude oil invades the water-filled pores and accumulates to form the oil reservoirs. The general influence of asphaltenes on wetting, has exclusively been widely studied as summarized by Kaminsky et al., (1998). These surface-active organic components are conveniently grouped as acidic components [represented by the carboxylic group, -COOH and quantified by acid number (Monsterleet et al., 1996; Fan et al., 2006)] and basic components [represented by -R3NH⁺ and quantified by base number (Dubey et al., 1993)]. A recent study (Hopkins P. A., 2016) revealed that these polar organic components are intrinsic to the crude oil and not only linked to the heavy end fractions.

The main wetting parameter in carbonates is reported (Andersen 1986a; Skauge et al., 1999;

Standnes et al., 2000; Zhang et al., 2005) to be the polar organic acids while the wettability of silica is more affected by the polar organic bases because of differing mineral surface charges. In carbonates, the rock surface is predominantly positively charged at natural reservoir conditions (Zhang et al., 2006), making it possible for negatively charged carboxylic material in oil to approach the rock surface. Silica is also typically negatively charged and positively charged bases could adsorb.

Knowledge of these phenomena and mechanisms has been applied by several researchers (Webb et al., 2005; Austad et al., 2005; Zhang et al., 2006; Strand et al., 2006; Zhang et al., 2007; Fathi et al., 2011; Fernø et al., 2011; etcetera) to study the possibility of reversing the initial wettability of carbonate reservoirs to the original state of preferential water-wetness, in order to maximize the recovery potential of the reservoirs through SI of injected water. Particularly, the concept of Smart Water EOR has received wide attention amongst scientist owing to the huge success of seawater flooding into the Ekofisk chalk field in the North Sea. Since Smart Water is aimed at wettability reversal, it is targeted at COBR systems exhibiting low water-wetting tendencies. In other words, initial wetting of the system considered for smart water application is key since it sets the potential to observe significant EOR effects.

Previously published work (Hopkins et al., 2016; Hopkins et al., 2017; Puntervold et al., 2007b;

Mjos et al., 2018) on outcrop chalk wetting using Stevns Klint chalk material have confirmed the assertion of polar organic acids being the principal wetting parameters as compared to the polar bases. In these studies, it was established that the adsorption is immediate, with retention equilibrium reached faster when flooding with crude oil of higher AN whilst the amount of adsorbed species remained the same. The instant adsorption implies that core wettability is not a function of ageing time, and that ageing is not a strictly necessary procedure for core preparations during laboratory experiments. It was established however, that the core wettability was a function of the amount of crude oil exposed to the chalk material. It is further revealed, how that restoration procedures should be done with caution; to acceptably restore reservoir core materials to representative initial wetting conditions during reservoir core characterization studies.

Since studies are frequently performed with outcrop chalk materials as correspondents to reservoir rocks, a comprehensive understanding of initial wetting requires a detailed investigation that also encompasses, the impact of the chalk mineralogical content.

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Skovbjerg et al., (2012) used atomic force microscopy (AFM) to show that the grain surfaces in offshore and onshore chalk are heterogeneous and contained nano-sized clay and silica particles.

By mass, chalk is dominated by calcite usually with only a minor percentage of silica (SiO2). The silica in chalk is quartz and opal-CT and minor amounts of silicate minerals are present, mainly in the form of clay. The effects of clay and silica on permeability and capillary entry pressure of chalk reservoirs in the North Sea has been reported by Fabricius et al., (2002). Divergent mechanical and physical characteristics of outcrop chalks based on mineralogical variance has also been documented in a study conducted by Megawati et al., (2015). Andersen et al., (2018) comparatively studied samples from five different outcrop chalks and noted silicates, present in unequal amounts, as the main mineralogical impurity within the chalk types. They further reported this mineralogical variance to have major control over chemo-mechanical interactions during flooding with NaCl and MgCl2 brine.

In terms of chalk wetting behavior, Strand et al., (2007) exposed two different outcrop chalk materials to the same crude oil and reported that the porous media exhibited different wetting characteristics as indicated by their wetting indices. Their observation pointed to the differing surface chemistry of the chalk types. The surface charge of silica and clay is predominantly negative and opposite to chalk, which is positive, at natural reservoir conditions, and it is therefore expected that the wetting condition will be affected by the content of silica and clay. The wetting behavior of chalk in relation to mineralogical heterogeneity is therefore imperative and worthy of investigation, especially as related to their surface reactivity towards the different polar organic components present in crude oil.

1.2 Problem Statement

For many years, scientists have been working to understand crude oil/brine/rock interactions responsible for altering rock wetting state and to implement this learning to develop novel solutions to improve oil production in carbonate reservoirs. Often, in such parametric studies, outcrop chalk material is used as analogs due to its availability and low-cost relative to obtaining reservoir cores.

But the wettability of chalk as documented, is influenced by the adsorption of polar oil components onto the mineral surfaces, which is influenced by several factors including the mineralogical composition of the material.

Available outcrop chalk materials are known to vary in mineralogical compositions of silica and clay. Due to the differing surface chemistry of calcite and silica mineral surfaces, it is expected that the degree of adsorption of acidic and basic components in crude oil will be different for the different chalk materials, which will influence the initial wetting conditions. An experimental investigation is therefore necessary to examine this impact and serve as additional knowledge to the already existing literature on chalk wetting by crude oil polar components.

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1.3 Objectives

The scope of this thesis is to investigate the adsorption potential of crude oil polar components onto impure outcrop chalk rock by quantifying the amounts of acidic components and basic components that can attach onto the chalk surfaces and its impact on initial wetting. Particularly, the purpose is to determine how silica content can impact the adsorption and to obtain an understanding of the chemistry involved in the mechanism. Further study is conducted to ascertain the extent that the amount of crude oil exposed to chalk matrix can influence the initial wetting. Findings from this study will serve as an additional learning to the Smart Water project at UiS.

This thesis opens with the theory of the research area that presents fundamental concepts required to understand the subject matter. A brief insight is provided into carbonate rock materials and the concept of Smart Water EOR in carbonates, followed by the experimental processes. Finally, the results are discussed in relation to the objectives and previous documented studies.

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2 Fundamentals

It is commonly agreed that hydrocarbons are the result of thermal alteration of organic material contained in sediment layers of source rocks and accumulated in porous geological reservoir formations by seals and traps. A useful resource as it is, the main aim is to discover and retrieve it from the natural subterranean environment. This chapter introduces some fundamental concepts of oil recovery with a notion to build a foundation that will introduce most of the terms required to sufficiently understand the subject matter of this thesis. Focus is given to defining enhanced oil recovery and carbonate reservoirs. All concepts in this thesis is presented by the assumption of a two-phase oil-water fluid system.

2.1 Oil recovery

Oil in the reservoir is extracted following several recovery processes that are traditionally divided into three convenient stages based on when they are likely to be implemented in the lifespan of an oil reservoir; primary recovery, secondary recovery and tertiary recovery.

2.1.1 Primary recovery

This refers to the initial stage of production where oil flows spontaneously to the surface owing to the natural energy in the petroleum reservoir. The core mechanisms cause pressure depletion of the reservoir natural pressure, in the form of gas cap drive, solution-gas drive, natural water drive, fluid and rock expansion, gravity drainage or using artificial pumps to drive oil to the surface (Ali et al., 1996; Puntervold, 2008). These forces in the reservoir can either act simultaneously or sequentially;

depending on the ability of its composition and properties to displace the oil, but at some point in time, the pressure will diminish. This stage of production recovers only a small fraction of the OOIP (Castor et al., 1981), typically ranging from 10% - 30%.

2.1.2 Secondary recovery

After natural reservoir energy diminishes, secondary recovery mechanism is employed by injection of external fluids, mainly to re-pressurize the reservoir and improve volumetric sweep efficiency.

The extra energy is usually provided in the form of gas injection or waterflooding, the latter being the most common. In this stage, depending on properties of the reservoir rock, oil and the injection fluid, usually 30-50 % of OOIP is recovered (Castor et al., 1981) with the remainder trapped in the porous media.

2.1.3 Tertiary recovery

This process uses miscible gases, chemicals and thermal energy to displace additional oil, when secondary recovery becomes uneconomical (Willhite et al., 1998). Additional energy of these kind added to the displacement mechanisms of primary or secondary methods have enormous potential to yield supplemental oil recovery (Lake, 2010).

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It is noteworthy, that a virgin reservoir need not be strictly produced according to this chronological sequence. Infact, today, most reservoirs are pressure maintained from day one. Plus, studies have shown that early implementation of optimal EOR techniques has increased advantage as opposed to the traditional recovery process.

Willhite et al., (1998) provide a demonstrative example regarding recovery from a heavy oil reservoir that highlights this assertion. They explain how that if the crude is sufficiently viscous, it may not flow at economic rates under the natural energy drives, so primary production would be negligible. Further on, for such reservoirs, waterflooding would not be feasible; therefore, the use of thermal energy might be the only way to recover a significant amount of oil.

In this case, a method considered to be a tertiary process in the normal chronological depletion sequence presented earlier, would be used as the first, and perhaps final, method of recovery.

2.2

Defining Enhanced Oil Recovery

The benefits of implementing innovative recovery operations earlier in the life cycle of a reservoir has disfavoured use of the “tertiary recovery” term and replaced it with a more complete term, Enhanced Oil Recovery (EOR). EOR is not restricted to a particular production phase or the outlined chronological order in the producing life of a reservoir (Stosur et al., 2003; Hite et al., 2004) and may be defined as the application of techniques for improving displacement efficiency or sweep efficiency, extending the lifetime of a reservoir, and ultimately the improvement of recovery by reducing residual oil saturation (Hopkins, 2016).

However, the action to implement an EOR method might be dictated by such factors as the nature of the reservoir fluid, availability of injectants and economics (Alvarado et al., 2010). Another term, IOR is widely used in the industry to encompass EOR as well as other activities such as reservoir characterization, improved reservoir management, infill drilling, etcetera. According to Taber et al., (1997), EOR simply means that something other than plain water or brine is injected into the oil reservoir, whereas IOR is a term used more broadly to encompass all optimize techniques used to increase the oil production. Available knowledge in the literature (Ali et al., 1996; Taber et al., 1997; Thomas, 2008) portrays that EOR may be split into the broad categories as shown in Figure 2.1 [revised after (Sunil et al., 2010)].

It is not yet established if any single EOR scheme is applicable to all petroleum reservoirs as a general method for enhancement of oil recovery; however, specific processes that are quite distinct from each other have been developed to address reservoirs with special characteristics. On such premise, Smart Water (Austad et al., 2005) injection indisputably deserves an inclusion since seawater is a superb EOR fluid to chalk ( (Puntervold et al., 2015; Puntervold, 2008) as it increases capillary forces and improves microscopic sweep efficiency through a wettability alteration process. This concept is discussed later in chapter 5.

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It is worth a mention, that the criteria for selecting a particular EOR process are complex because of the large number of petrophysical, chemical, geologic, environmental, and fluid properties that must be considered for each individual case.

Figure 2.1: Illustration of the production stages in a reservoir’s production life. Smart water is categorized and the essence for implementing EOR methods from day one is emphasized

2.3 EOR in carbonates

In the 1980’s, Roel et al., (1985) documented that about 50% of the world’s proven petroleum reserves were contained in carbonate reservoirs. Today, carbonates are estimated to hold more than 60% of the total remaining oil globally and 40% of the world’s gas. On average, Sunil et al., (2010) reports the worldwide recovery factor from conventional (primary and secondary) recovery concepts as only about a third of oil originally present in the reservoir. Hence, in most cases between 40 – 60 % of OOIP remains in the reservoir. This is attributed to carbonates being predominantly less water wet and naturally fractured with low matrix permeability. Thus, secondary recovery displacement fluids channel easily through these fractures from the injector to the producer and majority of the oil is left untapped within the matrix. This significant residual oil saturation, ROS (see Figure 2.2), is the main target of EOR in carbonates.

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Despite the great potential to improve oil recovery in carbonate reservoirs, EOR application in this area is very limited because of technical and economic challenges. Qing Sun et al., (2003) mentions that most of the field development schemes in carbonate reservoirs are restricted to waterflooding and gas flooding with low ultimate recovery factors

Figure 2.2: Percent of total oil reserves and recovery factor in carbonates (Suhal, 2016) In Figure 2.3, the most commonly implemented EOR methods in carbonates based on the global EOR database compiled by Vladimir et al., (2010) are presented. According to this database, the most frequent method is gas injection, followed by chemically based EOR methods and thermal methods, which represents only 3% of the total applied concepts in carbonates.

Figure 2.3: EOR field projects in carbonates (Suhal, 2016)

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Manrique et al., (2004) reports Carbonate EOR activities in the US to be dominated by CO2

flooding technologies either as continuous or Water Alternating Gas (WAG). This is because of the high availability of low-cost CO2 in the region. EOR chemical methods in carbonate reservoirs, especially polymer flooding, have been widely tested in the US carbonate reservoirs as well.

However, they have resulted in marginal contributions, relatively in terms of total oil recovered.

According to the North Sea EOR survey (Anwar et al., 2008), five (5) major EOR techniques have been tested in the region with WAG injection highlighted as the most common and successful technology in the region. In 1980, the Joint Chalk Research (JCR) programme was established by the Norwegian Petroleum Directorate (NPD), the Danish Energy Agency and the licensees in the North Sea’s chalk fields to undertake study into how recovery from the region’s rich carbonate reservoirs can be fully harnessed. It was resolved in 1983 to start a waterflood programme (using seawater) to press more oil out of the field. Three years later, crude output had doubled and estimated recoverable reserves were substantially increased (NPD, 2009). In recent times, the positive effects of seawater injection into the carbonate chalk reservoir has been attributed to a wettability reversal action induced by sulphate in the brine which contributed to the development of strong water wetness of the chalk matrix over the years of flooding. This revelation has turned the attention of many scholars and the industry to the implementation of water-based EOR techniques in carbonates.

The general goal of water-based EOR in carbonates is to imbibe water into the matrix and alongside expel the oil into the fractures, where it is further transported to the producer. This is possible when the injected brine has the potential to alter the unfavourable wetting state of the carbonate material.

A brine with such capability is ascribed the term “smart water”. The potential of smart water for EOR applicability in carbonates is well covered in the literature (Zhang et al., 2006; Zhang et al., 2007; RezaiDoust et al., 2009; Fathi et al., 2011; Seyed et al., 2012; Adepapo et al., 2014;

Puntervold et al., 2015).

2.4 Reservoir displacement Forces

Crude oil has limited intrinsic ability to drive itself from the tortuous pores of the underground rocks in which it is found; instead, it must be forcibly ejected by the accumulation of other fluids.

Normally, the methods for oil retrieval from the natural reservoirs will involve an immiscible displacement by water and/or gas of some kind to trigger and facilitate high levels of production.

The mechanism of this immiscible expulsion of oil can occur through spontaneous imbibition of water or forced imbibition.

Spontaneous Imbibition: Imbibition is the process of absorbing a wetting phase into the porous rock. Spontaneous imbibition, then, is when the absorption process occurs without any pressure driving the phase into the rock.

Forced Imbibition: This describes an absorption triggered by a pressure drive. A common term used in similitude is viscous flooding, or rather implicatively, forced displacement.

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Physically, in an oil reservoir, the most important in-situ driving forces are a) Viscous forces,

b) Capillary forces c) Gravity forces.

Viscous driving forces dominate forced imbibition and the latter two are responsible for spontaneous imbibition.

For oil displacement in an ideal EOR process, the overall displacement efficiency (E) is considered a product of macroscopic and microscopic displacement forces (Willhite et al., 1998) and given by;

𝐸 = 𝐸_𝑉 ∗ 𝐸_𝐷 (2.1)

Where ED and EV are the microscopic and macroscopic displacement efficiencies respectively.

Macroscopic displacement efficiency: The 𝐸_𝑣, also called sweep efficiency, measures how effectively the displacing fluid sweeps out the volume of the reservoir. It shows the effectiveness with which the fluid percolates through the system and contacts the EOR target oil. The most important parameter controlling this term is the mobility of displacing fluid as against that of the displaced oil.

Microscopic displacement efficiency: The ED measures how effectively the EOR injection fluid mobilizes the oil at those places in the reservoir where it contacts the oil. Basically, it focuses on the effectiveness of an oil recovery process at the pore scale level to reduce the residual oil saturation (Sor) to the barest minimum. Interfacial tension, and rock wettability state are the key controlling parameters.

2.4.1 Capillary Forces

When two immiscible fluids coexist in the pores of a reservoir section, a pressure discontinuity arises across the interface separating the two fluids. This pressure difference is termed Capillary Pressure (Pc), and classically defined as the pressure in the non-wetting phase minus pressure in the wetting phase. Mathematically, Pc is expressed as;

𝑃_𝑐 = 𝑃_𝑁𝑊 − 𝑃_𝑊 (2.2)

Evidently, the capillary pressure may assume positive or negative values depending on the fluid pressures. For a two phase oil-water system, Pc is defined as;

𝑃_𝑐 = 𝑃_𝑜− 𝑃_𝑤 = ^{2𝜎𝑐𝑜𝑠𝜃}

𝑟 (2.3)

Where: Po & Pw are the oil and water phase pressures across the interface respectively;

𝜎 = interfacial tension (IFT); 𝜃 = contact angle; r = pore channel radius

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Drive forces due to capillary are the consequences of the interplay of pore dimension and geometry, pore throat size, wettability and the surface/interfacial tension generated by the fluids and rocks of a given reservoir system. Capillary forces are a decisive influence on oil recovery efficiency and could act against or in favor of the production depending on the formation framework.

Displacement in fractured reservoir systems, like carbonates is only supported by positive capillary forces (Cuiec et al., 1994).

The strong capillary forces encourage self-uptake of water through spontaneous imbibition to eject oil. However, in a non-fractured reservoir, strong capillary forces during waterflooding might trap oil and reduce oil production (Strand, 2005). In carbonates, the desired means to induce positive capillary forces is to reduce cos𝜃 (in equation 2.3) by a wettability reversal to mixed- or water-wet conditions and promoting the imbibition process. The definition of 𝜃 is given in section 4.2.1 2.4.2 Gravity Forces

As is expected, immiscible fluids will segregate according to densities by gravity in the porous rock, with the densest fluid (water) at the bottom. The main driving force is determined by the fluid density (Lake, 2010) and plays a significant role in the multiphase fluid system that is usually encountered in the reservoir. Depending on the layer wherein displacement is occurring and differences in fluidic densities, the displacing fluid can segregate; influencing the displacement front and resulting in an ineffective recovery efficiency through overriding or under riding.

The hydrostatic pressure difference between oil and water owing to gravity can be given by;

𝑃_𝑑= (𝜌_𝑤− 𝜌_𝑜) ∗ 𝑔 ∗ 𝐻 (2.4)

Where: 𝜌_𝑤& 𝜌_𝑜 = water and oil phase densities respectively; g = gravitational acceleration constant; H = height between the fluid columns.

Chen et al., (2000) highlights that gravity forces can be a major concern when density differences between oil and water are large and can also be important at low oil-water IFT conditions.

Implicatively, for stationary laboratory situations when an oil saturated core is submerged in water, segregation by gravity will play a dominant role in the imbibition process since the capillary forces are then reduced (Schechter et al., 1994). It should be recognized, then, that spontaneous imbibition can be driven either by capillary or gravity forces and is a function of interfacial tension (IFT), wettability, density difference and characteristic pore radius.

2.4.3 Viscous Forces

When fluids flow in a porous rock, viscous forces are reflected in the magnitude of pressure drop that occurs as a result of the flow (Willhite et al., 1998; Pinerez, 2017). The concept of fluid flow in reservoir rock is inextricably related to the rock permeability. Permeability is a sole property of the porous reservoir rock that determines how fluids are transmitted through it. This rock characterization was first defined mathematically (see equation 2.5) by Henry Darcy in 1856 and it is an important expression when considering fluid flow in porous media.

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12 𝑞 =^𝑘𝐴

μ Δ𝑝

𝐿 (2.5)

Where: q is the fluid flow rate; k is permeability; A is cross-section area; μ is fluid viscosity; L is length of flow path and Δ𝑝 is differential pressure.

Usually, by simplification, the flow path in a porous media is considered as a bundle of parallel capillary tubes (Pinerez, 2017). Here, the flow automatically (due to the assumption) becomes laminar and the pressure drop over any length of fluid flow path can be calculated using the Poiseuille’s law equation;

∆𝑃 =^8𝜇𝐿

𝑟² 𝑣𝑎𝑣𝑔

𝑔_𝑐 (2.6)

Where: ∆𝑃 = Pressure difference across capillary tube; 𝜇 = viscosity; L = length of tube, vavg = average flow velocity in tube; r = tube radius, gc = conversion factor.

The prime objective of EOR operations is to mobilize and displace the significant volumes of oil (usually remaining as droplets) left behind after conventional recovery operations. Laboratory studies (Taber, 1969) have indicated that residual oil can be recovered if the pressure differential due to viscous flow is sufficient to overcome capillary forces. The interplay of viscous and capillary forces is captured through the dimensionless group called capillary number, Nca. For a drive mechanism of water displacing oil, Nca is given as;

𝑁_𝑐𝑎 =^𝐹^𝑣

𝐹_𝑐 = ^𝑣𝜇^𝑤

𝜎_𝑜𝑤𝑐𝑜𝑠𝜃 (2.7)

Where Fv = viscous force, Fc = capillary force, v = interstitial velocity, 𝜇_𝑤 = water phase viscosity.

From equation 2.7, a high capillary number is a requirement to effectively displace oil. Clearly, this can be achieved by reducing cos𝜃 via wettability alteration and this is the motivation for smart water EOR in carbonates. Morrow (1979) asserts that if the ratio of viscous to capillary forces is raised sufficiently, almost complete recovery of residual oil can be achieved. A review study of the various methods to represent this interplay was reported by Larson (1977).

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3 Carbonate rocks

In this chapter, a brief definition of carbonate rocks (limestone, dolomite and chalk) is given with an attempt to provide an understanding into the general classification of carbonates based on mineralogy. The geological and petrophysical heterogeneity of carbonates is faintly highlighted with emphasis given to chalk as a reservoir rock material.

3.1 Classification of carbonate rocks

Carbonates are sedimentary rocks formed either by the deposition and lithification of organic matter sourced from calcareous plant and animal debris, or directly from chemical precipitation of concentrated solutions. Often, they are denoted as biogenic sedimentary rocks (Bissel et al., 1967), to infer their composition of organic material produced by marine living organisms (Figure 3.1).

While alive, these organisms extracted Ca²⁺ and CO32- ions from the water and used them to form the mineral CaCO3 in the construction of their cellular structures.

Carbonate rocks can be attributed as clastic when formed from fragmented carbonate rocks as opposed to non-clastic if derived from preserved sediments. A bio-clastic rock (Skinner et al., 1991) is a rock type composed of fragmented organic material, that has not been fully homogenized by chemical processes (Puntervold, 2008). Limestone and Dolomite may be classified as clastic or non-clastic, whereas chalk is often classified as bio-clastic. From the Petrology point of view, carbonate rocks have complicated and varied depositional patterns and are subject to extensive post-depositional alteration which can radically alter the original porosity and permeability relationships. Several authors have proposed terms for general classification based on this premise and are extensively discussed by Mazzullo et al., (1992).

Carbonates are abundant and vary in structure, chemical and physical properties depending on the composition of the minerals present. At their basic framework, however, is the fundamental anionic structure of CO32- so it is unsurprising to find reports where geologists generally classify carbonate rocks as those containing more than 50% of carbonate minerals. Some common minerals are calcite (CaCO3), Aragonite (CaCO3), Siderite (FeCO3), Magnesite (MgCO3), Dolomite (CaMg(CO3)2), and Ankerite (CaFe(CO3)2) (Bjørlykke, 1989). Calcite and Dolomite form the two most abundant and together, make up 90% of all naturally occurring carbonates (Bissel et al., 1967; Bagrintseva, 2015).

In general, Limestone is classified as a sedimentary rock in which the carbonate fraction exceeds the non-carbonate constituents (greater than 50% CaCO3; either as calcite or aragonite).

Conversely, the term Dolostone is reserved for those rocks containing more than 50% of the mineral dolomite (Mazzullo et al., 1992). In nature, the two are commonly intimately associated but as relating to their depositional origin and subsequent diagenesis, and chemistry, very different.

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Figure 3.1: Carbonate material growing in clear water (a), and images of carbonate- source eukaryotes with high degree microscopes.

Some writers (Pettijohn, 1975; Mollazal 1961; Bissel et al., 1967; Mazzullo et al., 1992) have recognized classification based on the intergradations of these common carbonate-end members as an excellent ground for carbonate rock recognition at the basic level. Pure limestone, (90% calcite), dolomitic limestone (20-50 % dolomite), calcitic dolomite (50-90 % dolomite) were proposed.

Originally, only calcite is formed directly and then may undergo a microchemical process of calcium carbonate dissolution and dolomite precipitation. This diagenetic process to yield the dolomite mineral is called dolomitization (see equation 3.1). Dolomite is made up of layers of CO32- with alternating layers of Ca²⁺ and Mg²⁺ in between (Puntervold, 2008). The process is reversible and may be triggered in the presence of high calcium waters (Lucia, 1999).

2CaCO3 + Mg²⁺ ⇌ CaMg(CO3)2 + Ca²⁺ (3.1)

Evidence of non-carbonate mineral present in carbonate rocks (Graf, 1960) exist with detrital quartz as the most common impurity (Fabricius et al., 2002). In addition, various forms of authigenic silica, evaporites (gypsum and anhydrite), clay minerals and glauconites are present in various abundances in many limestones and dolomites (Mazzullo et al., 1992).

It is noteworthy to mention that other common classification schemes are used by geologists that may be based on grain size, compositions or texture.

a b

c d

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3.2 Geochemistry of Chalk

Chalk is classified as a friable, fine-textured Limestone (Pettijohn, 1975). It is regarded as a pelagic deposit formed from calcareous debris of the unicellular planktonic algae, coccolithophorids.

Coccolithophorids (see figure 3.1d) have a unique exoskeleton built of internally secreted calcite tablets that are arranged in rings known as coccoliths. These coccoliths are arranged into a hollow coccosphere which encapsulates the soft part of the living algae. On death, the coccospheres falloff and coccoliths are released to form the pelagic deposits that later become chalk (Hardman, 1982).

Since the primary constituent of coccolith is calcium carbonate, the resulting chalk is mainly composed of calcite crystals that are held together either by organic material or through mechanical interlocking. This makes chalk a rock of great chemical stability (Hanken et al., 2015).

In addition, chalk may contain coarser calcite grains from planktonic and benthonic foraminifera shell debris of various kinds plus silt-size quartz grains and clay minerals (Jørgensen, 1986). But in general, (Hardman, 1982) emphasizes chalk as a remarkably pure form of calcium carbonate since in many existing forms, these impurities comprise less than 5% of the rock. He notes, in some cases, that early and late stage diagenesis can result in cryptocrystalline silica being concentrated in nodules and tabular layers know as flints. An image of a typical chalk rock is presented in figure 3.2.

Figure 3.2: SEM image of chalk showing the coccolithic rings and pore spaces.

In Chalk, the calcite crystals (Donaldson et al., 2008), composed of complex ions of calcium and carbonate ions are held in a cubic structure with each Ca²⁺ centered between two CO32-. These ions are exposed on the rock surface in an alternating cycle. Calcium, in bonding to CO32- achieves a stable octet by losing its two outer electrons that results in a doubly charged positive cation, Ca²⁺. Meanwhile, the oxygens are bonded to the carbons through strong covalent bonds with completed electron octets, leaving a very weak negative electron cloud, compared to the exposed Ca²⁺. This makes the net surface charge on the rock surface positive and offers the reactive potential to undergo sorption processes when in contact with negatively charged species. Legens et al., (1999)

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conducted zeta potential measurements of calcite in water and reported a constant value of +32mV as the solution pH is changed from 6.5 to 11. It is informed in their report that even in the presence of 0.1M NaCl, the zeta potential remained linear with respect to increasing pH but was stable at a value equal to about +15mV. It is also reported (Puntervold, 2008) that chalk surface is positively charged if the surrounding brine’s pH is < 8. This is also verified by other scholars (Pierre et al., 1990; Zhang et al., 2006; Dawoud et al., 2016; Hassan et al., 2017) who investigated carbonate surface charge versus surrounding brine pH and salinity. It must be noted thus, that carbonates (chalk, dolomite etcetera) predominantly have an overall electrically positive surface, which should favour oil wetting by adsorption of negatively charged polar species in crude oil at favourable conditions.

3.3 Chalk as a reservoir

Chalk forms a fine grained micropore reservoir (i.e. composed of particles which are mainly single crystal laths of calcite produced by the disaggregation of coccoliths) with particles in the size range of 0.5 - 3 microns and pore throat sizes in the optimum case ranging from 0.1 – 1 micron. This makes chalk reservoirs highly porous (black spaces in figure 3.2), with typical values of 35 – 45 % but exhibit low permeabilities, usually in the range 0.1 – 7mD (Hardman, 1982).

Extensive fractures are common to chalk reservoirs and depending on its cautious exploitation, can play a very important role in the oil recovery process as transport routes for oil drained from the matrix blocks during spontaneous imbibition of water.

Chalk reservoir quality is controlled by a variety of factors, predominated by; the purity in terms of CaCO3 content of sediments, the rate of deposition of chalk minerals which in turn determines the degree of early frame-work cement, the tectonic setting of the field area during chalk deposition and the size distribution of the coccoliths being deposited. Hardman (1982) asserts that nearly all reservoir quality variation can be related to these four factors. Ekofisk and Valhall oilfields are examples of chalk reservoirs along the NCS. Besides these Cretaceous to Paleocene deposits in the North Sea, Chalk deposits in the Gulf Coast and in the West interior seaway provinces of North America are important hydrocarbon-producing sites (Mazzullo et al., 1992).

3.4 Outcrop chalk materials

Outcrop chalk materials are used as the primary data sources during laboratory parametric studies.

Contrary to real reservoir rock samples, which are deeply buried, outcrop chalk is cheap and readily available (Puntervold, 2008). These outcrops, despite having similar lithology, can contain fewer heterogeneities compared with reservoir material and the decision regarding the choice of outcrop material to be used in geochemical and flooding experiments is crucial. When reservoir chalk characterization is based on testing of outcrop chalks, understanding the diagenetic mechanism and composition of the outcrop material is key. Particularly, silica type and content have been shown to affect the wettability (Strand et al., 2007) and mechanical strength (Megawati et al., 2015;

Andersen et al., 2018) of the chalk rock. The geological descriptions of four types of outcrop chalks, Stevns Klint, Aalborg, Liege and Beer Stone are summarized in Table 1

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Table 1: Geological description of some outcrop chalks (Milter et al., 1996; Puntervold, 2008) Stevns Klint Aalborg Liege Beer Stone Kansas Origin Singerslev,

Denmark

Rørdal, Denmark

Halembaye, Belgium

Beer, England

Niobrara, USA Geologic age Maastrichtian Maastrichtian Campanian Turonian Late

Cretaceous Silica content

(wt%) ~ 1 2-7 < 2 - < 2

Porosity (%) 45-50 44-48 40 24-30 37-40

Permeability

(mD) 2-5 3-5 1-2 1-2 1-2

Specific surface

area (m²/g) ~2 ~4 ~2 ~1 < 3

3.4.1 Aalborg chalk material

Aalborg chalk is located in the Rørdal quarry of Denmark. This Rørdal member of the chalk outcrop group is a cyclic-marl unit, about 10m thick, sandwiched between pure white chalks. Aalborg chalk cores were classified by Andersen et al., (2018) as coccolithic mudstones with large numbers of foraminifera shells and even layers of macrofossil debris. Their Coccolithophores are well preserved, but commonly show some overgrowth.

Surlyk et al., (2010) reported the coccolith and brachiopod data of this outcrop chalk member as belonging to the UC20b-c^BPnannofossil zone of the North Sea scheme for the Upper Cretaceous Boreal province, and the semiglobularis-humboldtii brachiopod zone, both indicative of a lower upper Maastrichtian age. Their interpretation of the Aalborg Isotope data showed that it represents a distinct early late Maastrichtian cooling event.

Typical characteristics of Aalborg chalk is the abundance of well-developed opal-CT (SiO2.nH2O), formed in blades and lepispheres, present in the non-carbonate phase and occur in the large intra- fossil pores (Megawati et al., 2015). In most outcrop chalks, like Stevns Klint, silica fraction is mostly dominant as quartz. opal-CT, is an abbreviation for a group of silica-stable minerals formed from pelagic phyto-plankton diatoms. Originally, these diatoms are composed of amorphous colloidal silica (opal-A) and are diagenetically lithified upon deposition in water bodies to the more stable opal-CT. At high temperatures, as in the subsurface reservoirs, the opal-CT in turn is altered to a microcrystalline quartz, which is the final and most stable form of silica.

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It forms the main source of impurity in the Aalborg outcrop chalk that plays a significant role in porosity and reactivity modification of the outcrop and introduces a non-carbonate chemistry that will most likely impact laboratory results.

Andersen et al., (2018) investigated geochemical properties of Aalborg by flooding cores with MgCl2 and NaCl brine. There was minute dissolution of calcite and Si-bearing minerals, but no new mineral precipitation was observed during NaCl injection. However, silica dissolution and reprecipitation (during MgCl2 injection) as well as a significant concentration of Si⁴⁺in the effluent was observed. Their findings suggest that the reactive presence of opal-CT in Aalborg plays a crucial role in the whole geochemical behavior of the outcrop rock.

When Strand et al., (2007) performed SEM analysis on Aalborg chalk, thin clay flakes were reported and suspected to be smectite after EDS (morphological and chemical) analysis showed presence of Aluminium (Al), Magnessium (Mg) and Potassium (K). Skovbjerg et al., (2012) used X-ray Diffraction (XRD) to analyze outcrop chalk residue after acid dissolution and quantified the non-calcite part to be between 1.8 and 4.6 % of which clay minerals contributed between 0.9 to 1.7

%. They also imaged 135 areas on different samples of chalk and reported laths on 75% of these areas. Although no chemical compositional analysis was conducted, they concluded that the observed laths, based on the size and shape, were clay minerals. They characterized the clay to consist of smectite (>85%) and small amounts of illite, kaolinite and mixed layer illite/smectite phases. It is established that due to their thinness, these clay coatings are very hard to observe in SEM and estimates of their size and distribution patterns are nearly impossible to obtain.

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4 Introduction to Wettability

4.1 Wettability classification

Wettability describes the preferential tendency of a fluid to spread on or adhere to the surface of a solid material in the presence of other immiscible fluids (Donaldson et al., 2008). It plays a direct role in determining the relative permeabilities and distribution of reservoir fluids, and ultimately the success or failure of an EOR operation by drive fluids. In the reservoir, wettability of the crude oil/brine/rock (COBR) system and its effect on oil recovery is an extremely challenging problem and many studies (Donaldson et al., 1969; Andersen, 1987; Morrow, 1990; Cuiec, 1991;

Drummond et al., 2004; Donaldson et al., 2008) have been dedicated to understanding its complexity. In the reservoir, several COBR interactions have established an equilibrium that has defined a specific wetting condition prevailing in the subterranean rock, which are suitably categorized into four general forms(Donaldson et al., 2008);

a) water-wet b) oil-wet

c) fractional wettability d) mixed-wettability

A COBR system is considered water-wet or oil wet when more than 50% of its surface is wet by water or oil respectively. In water-wet conditions, if the water saturation is reduced to its irreducible saturation (Swi), water remains as a continuous phase in the small pores throughout the rock structure and the oil is reserved to larger pores with high enough saturation to exist as a continuous phase. A rock under such wetting state will spontaneously imbibe water (the wetting phase) to expel the oil (which is non-wetting) until a state of static equilibrium is reached between the capillary and surface energy forces (Donaldson et al., 2008). As the water saturation increases, the oil phase experiences a snap-off effect, becoming discontinuous and existing as globules in the center of the larger pores (Hopkins, 2016). A reverse of the above-mentioned fluid distribution through the pore network is true for an oil-wet system as illustrated in figure 4.1. The terms water- wet and oil-wet are included in the frequently used term homogeneous wettability.

Figure 4.1: Illustration of homogeneous wettability (Willhite et al., 1998)

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Fractional wetting typifies heterogeneous wetting of the pore surfaces where the preferential wetting is randomly distributed throughout the rock. Mixed wetting, introduced by Salathiel (1973), also characterizes a condition where the small pores in the pore network are water-wet and saturated with water, but the larger pores are oil-wet and filled with oil that connects to form a continuous path throughout the rock matrix. Both terms are included in the often-used general term neutral-wettability. Under such wetting state of distinctive oil-wet and water-wet zones, water and oil may be spontaneously imbibed respectively at high oil and water saturations (Andersen 1987;

Cuiec, 1991; Agbalaka et al., 2008).

The wetting phase that will result in optimal recovery of oil has been the subject of intense debate, as pointed out by Agbalaka et al., (2008) in a review of wettability effect on oil recovery. The reason for this divergence in observed report is attributable to a number of modifying factors which include; constraint of/difficulty in wetting state reproducibility, the lack of unified standard or procedure for coring, core handling and core storage and the wetting state characterization method adopted.In this regard, many published reports have proposed ways of maintaining and restoring in-situ core wetting state to ensure that reservoir rock wettability is accurately measured and used in laboratory and/or field-wide determination of recovery efficiency. A study by Puntervold et al., (2007), for example, suggested a new method to prepare outcrop chalk cores for wettability and oil recovery studies at low Swi and is employed during core preparations for experiments conducted in this thesis work.

4.2 Wettability measurement techniques

A wide variety of methods have been proposed for wettability assessment of surfaces. This section introduces the quantitative measurements; contact angle, Amott water index, United States Bureau of Mining (USBM) and a more modern technique; Chromatographic wettability test. Using imbibition as a qualitative method is also briefly described. The terms imbibition and drainage will be frequently used in this section. Drainage defines the process that leads to increased saturation of the non-wetting fluid and imbibition refers to increase in the saturation of the wetting fluid. By considering water to be wetting, Imbibition, the increase of water saturation, may proceed by either spontaneous imbibition or forced imbibition (see also section 2.4). Similarly, the increase in oil saturation may proceed by spontaneous drainage or forced drainage.

4.2.1 Contact angle measurements

The surface energies of typical COBR system as shown in figure 4.2, are related by Young’s equation:

𝜎_𝑜𝑠− 𝜎_𝑤𝑠 = 𝜎_𝑜𝑤𝑐𝑜𝑠𝜃 (4.1)

Where 𝜎_𝑜𝑠 is the interfacial energy between the oil and solid, 𝜎_𝑤𝑠 is the interfacial energy between the water and solid, 𝜎_𝑜𝑤 is the interfacial energy [interfacial tension (IFT)] between the oil and water and 𝜃 is the contact angle of the water/oil/solid contact line (Andersen , 1986).